Because of the improvements provided by two piece plungers, plunger lifts have become considerably more common in hydrocarbon wells, particularly in lifting water and condensate from gas wells. A fast growing segment of artificial lift equipment is the use of plungers that lift sufficient liquids to keep otherwise marginal gas wells producing. Of course, high oil and gas prices contribute to the desire to keep older wells producing and two piece plunger lift systems have been effective in this regard. Typical two piece plunger lift systems are shown in U.S. Pat. Nos. 2,001,012 and 6,467,541.
Gas wells reach their economic limit for a variety of reasons. A common reason is that gas production declines to a point where the formation liquids are not readily moved up the production string to the surface. Two phase upward flow in a well is a complicated affair and most engineering equations thought to predict two phase flow are only rough estimates of what is actually occurring. A major reason is the changing relation of the liquid and of the gas flowing upwardly in the well. At times of more-or-less constant flow, the liquid acts as a upwardly moving film on the inside of the flow string while the gas flows in a central path on the inside of the liquid film. The gas flows much faster than the liquid film. When the volume of gas flow slows down below some critical value, or momentarily stops, liquid runs down the inside of the flow string and accumulates in the bottom of the well, often in sufficient quantity to reduce or stop flow from the formation into the well. If flow stops, the well has to be swabbed, at considerable expense, to bring it back on production.
One of the areas of plunger lifts, both of the one piece and two piece types, that needs improvement is the seal that operates between the piston and the inside of the production string. It will be immediately appreciated that if the plunger is successful in bringing up more liquid on each trip and leaving less liquid in the production string, results will improve. The production string of most wells comprises threaded pipe joints, typically 2⅜″ O.D. or 2⅞″ O.D., although smaller and larger sizes are known. The inside surface of such production strings is not a perfect cylinder for a variety of reasons. First, there is a gap in the coupling of all threaded production strings where liquid collects and is bypassed by the plunger or piston. Second, no production string has a perfect inside surface when new and, manifestly, much used tubing with all its imperfections is run in new shallow wells. Third, during use there is sometimes a buildup of minerals on the inside surface. Fourth, corrosion can cause buildup on the inside surface or erosion of the inside surface, depending on the type of corrosion. Fifth, there are other mechanisms at work to erode the inside surface, such as high volume sand-laden production when a well is being cleaned up after a frac job. Sixth, production pipe can become egg shaped because of handling or mishandling during transportation or when being run into a well. For these and other reasons, experience has shown that one cannot use a non-pad type plunger of more than about 1.890-1.900″ diameter in a nominally 1.995″ I.D. pipe, which is the standard nominal internal diameter of 2⅜″ tubing. Attempting to use a larger diameter plunger creates too great a risk of sticking the plunger in the production string. Similar caution is necessary in production strings of other sizes.
In response to these clearance problems, plungers are typically made significantly smaller than the nominal I.D. of the production string and rely on an exterior sealing structure to minimize bypass of gas and liquid around the outside of the plunger. There are a wide variety of prior art seal structures, including grooves on the exterior of the plunger causing turbulent zones reducing bypass around the exterior of the piston, whisker type seals incorporating a multiplicity of bristles that reduce bypass around the exterior of the piston, pad type devices which expand under spring forces to abut the inside of the production string, and the like. This invention most nearly relates to the pad type seals of plungers used to lift liquids in hydrocarbon wells. Prior art pad type plungers include a spring that provides all, or almost all, of the force biasing the pad into engagement with the inside of the production string. Disclosures of some interest relative to this invention are found in U.S. Pat. Nos. 6,045,335; 6,591,737; 6,644,399; 6,746,213 and 6,669,449.